Low sulfur motor gasoline (low sulfur “mogas”) requires the production of low sulfur blend stocks for the mogas pool. A primary blend stock is derived from catalytically cracked (e.g., FCC) naphthas which, in addition to unwanted organic sulfur compounds, contain olefins desirable for meeting octane number rating requirements. Sulfur must be removed to meet environmental requirements. It is frequently beneficial to distinguish two different types of naphtha hydrodesulfurization processes, selective and non-selective. In selective naphtha hydrodesulfurization, it is desired to remove as much sulfur as possible, while preserving olefins. In hydrotreating or non-selective hydrodesulfurization, heteroatom removal is the primary goal, with olefin preservation being a secondary concern. In non-selective hydrodesulfurization, sulfur removal is increased by increasing the process severity and/or changing or increasing the amount of catalyst. However, increasing the severity of the reaction conditions for sulfur removal in a selective naphtha hydrodesulfurization process results in a loss in octane rating, due to olefin saturation by hydrogenation.
In hydrodesulfurization, naphtha is reacted with a hydrogen-containing treat gas over a sulfided hydrodesulfurization catalyst, which forms H2S and a sulfur-reduced naphtha. Such catalysts are known and typically contain at least one catalytic component of a metal of Group VI or a non-noble metal of Group VIII, and more often a catalytic component of both a Group VI metal and a Group VIII non-noble metal. In addition to having catalytic activity for removing sulfur and other heteroatoms, these naphtha hydrodesulfurization catalysts have hydrogenation activity, which saturates some of the desirable olefins. Such processes are disclosed, for example, in U.S. Pat. Nos. 5,286,373; 5,525,211; 5,423,975, 5,985,136 and 6,231,754. The hydrogen-containing treat gas for the hydrodesulfurization is obtained from a variety of sources, such as continuous regeneration naphtha reformers, steam-methane reformers, natural gas-hydrogen blends, pipeline hydrogen, steam cracker by-product gas, hydrogen recovered from refinery fuel gas streams and the like. Some such steams can contain from 100-2,000 or more vppm COX. Because the process variables noted above are adjusted to achieve the desired level of sulfur removal in non-selective naphtha hydrodesulfurization, the presence of COX levels on the order of 100-200 vppm in the treat gas has typically been ignored and, as a consequence, this has also not been considered important in selective hydrodesulfurization.